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Unconventional Hydrocarbon Resources: Techniques for Reservoir Engineering Analysis

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Unconventional Hydrocarbon Resources: Techniques for Reservoir Engineering Analysis

Reza Barati, Mustafa M. H. Alhubail

ISBN: 978-1-119-42032-3 April 2020 American Geophysical Union 460 Pages

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Description

Unconventional shale oil and shale gas plays have gained more attention since they are the sole cause of improvements in making the oil and gas business in US and some other companies getting closer to become independent.

There is not one comprehensive book with a set of examples and projects that show the step by step approach of calculating the resource volume and optimizing the hydraulic fracturing of unconventional resources. Thus, the primary author has just developed a course in the area of Unconventional Resources from scratch using a unique content that comes from his 10-years of experience in this area. Primary author, Reza and three of his graduate students, developed a unique set of examples, homework assignments, and projects for this course using valuable datasets from the Bakken, Woodford, Mississippian play, and Eagle Ford. He realized that this discipline suffers from a lack of a comprehensive textbook in this area that contains relevant examples, assignments, and projects for students to work on. Thus, as discussed above, unconventional resources have become a game changer in oil and gas industry since early 2000s.

Engineering of Shale Resources will be a valuable resource to students, both graduate and undergraduate, and instructors as well as junior staff of oil and gas operators and service companies both nationally and internationally.

1        Chapter One: Introduction to Unconventional Hydrocarbon Resources

1.1     Background

1.2     Overview of Shale Revolution

1.2.1       What Led to the Shale Phenomenon

1.2.2       Importance of Recent Unconventional Resource Discoveries

1.3     Basic Definitions and Classifications

1.3.1       Conventional and Unconventional Resources

1.3.2       Unconventional Oil-bearing Sediments

1.3.3       Unconventional Natural Gas Resources

1.3.3.1     Deep Natural Gas

1.3.3.2     Geo-pressurized Zones

1.3.3.3     Tight Natural Gas

1.3.3.4     Shale Gas

1.3.3.5     Coalbed Methane

1.3.3.6     Methane Hydrates

1.4     U.S. and International Unconventional Plays

1.4.1       North America Unconventional Shale Plays

1.4.1.1     Barnett Shale

1.4.1.2     Bakken Formation

1.4.1.3     Marcellus Shale

1.4.1.4     Utica Shale

1.4.1.5     Chattanooga Shale

1.4.1.6     Eagle Ford Shale

1.4.1.7     Wolfcamp Shale

1.4.1.8     Niobrara Shale

1.4.1.9     Woodford Shale

1.4.1.10     Fayetteville Shale

1.4.1.11     Haynesville Shale

1.4.1.12     Monterey Shale

1.4.1.13     Muskwa Shale

1.4.1.14     Besa River Shale

1.4.1.15     Colorado Shale

1.4.1.16     Eagle Ford Shale in Mexico

1.4.1.17     Tithonian and Tithonian La Casita

1.4.1.18     Pimienta Formation

1.4.2       South America Unconventional plays

1.4.2.1     Vaca Muerta Formation

1.4.2.2     Los Molles Formation

1.4.2.3     Estratos con Favrella Formation

1.4.2.4     Ponta Grossa Formation

1.4.2.5     Los Monos Formation

1.4.2.6     La Luna and Capacho Formations

1.4.3       Europe Unconventional Plays

1.4.3.1     Bazhenov Formation

1.4.3.2     L. Silurian and L. Carboniferous Formations

1.4.3.3     Llandovery Formations

1.4.3.4     Permian-Carboniferous Formation

1.4.4       Middle East Unconventional Plays

1.4.4.1     Qusaiba Formation

1.4.4.2     Shilaif Formation

1.4.4.3     Diyab Formation

1.4.4.4     Athel Formation

1.4.4.5     Batra Formation

1.4.4.6     Bahrain Shale

1.4.4.7     Dadas Formation

1.4.5       Africa Unconventional Plays

1.4.5.1     Whitehill Formation

1.4.5.2     Frasnian Formation

1.4.5.3     Tannezuft Formation

1.4.5.4     Sirte Formation

1.4.5.5     Khatatba Formation

1.4.6       Asia Unconventional Plays

1.4.6.1     Longmaxi Formation

1.4.6.2     Ketuer Formation

1.4.6.3     Sembar Formation

1.4.7       Australia Unconventional Plays

1.4.7.1     Goldwyer Formation

1.4.7.2     Nappamerri Formation

1.4.7.3     L. Kyalla Formation

1.5     Unconventional Resources Interpretation Workflow

1.5.1       Workflow of Unconventional Reservoirs

1.6     Future Projection and Challenges

1.7     General Remarks

1.8     Problems

1.9     References for Additional Reading

2        Chapter Two: Petrophysical Properties of Unconventional Reservoirs

2.1     Background

2.2     Petrophysics

2.2.1       Evaluation of Rock Properties

2.2.1.1     Mud Logging

2.2.1.2     Coring

2.2.1.3     Well Logging Measurements

2.2.2       Shale Volume

2.2.3       Gamma Ray spectroscopy

2.2.3.1     Clay Typing

2.2.3.2     Mineralogy

2.2.3.3     Ash layer detection

2.3     Lithology Evaluation

2.3.1       Lithology Measurements using Cross-plots

2.3.2       Lithology Measurements Using a Combination of Logs

2.3.2.1     Litho-Density Tools and Their Application

2.3.2.2     Dual-Mineral Analysis

2.3.2.3     Three-Mineral Analysis

2.3.3       Lithology Measurements Using the Diffuse Reflectance Infrared Fourier Transform Spectroscopy Techniques 

2.4     Porosity

2.4.1       Porosity Measurement

2.4.1.1     Porosity Evaluation Using Well Logs

2.4.1.1.1     Density Logs

2.4.1.1.2     Neutron Logs

2.4.1.1.3     Acoustic Logs

2.4.1.2     Porosity Evaluation Using Combination of Different Logs and Cross-Plots

2.4.1.2.1     Neutron-Density Logs

2.4.1.3     Porosity Evaluation by Helium Expansion and Helium Injection

2.4.1.4     Porosity Evaluation Using Nitrogen Adsorption

2.4.1.5     Porosity Evaluation Using NMR

2.4.2       NMR Core Porosity for Shales

2.5     Pore Size Distribution

2.5.1.1     Pore-Size Distribution Using NMR Logging

2.5.1.2     Pore-Size Distribution Using Nitrogen Adsorption

2.6     Permeability

2.6.1       Unsteady-State Permeability Measurement Methods

2.6.1.1     The GRI method

2.6.1.2     Pulse Decay Method

2.6.1.3     Modified Pulse Decay Method

2.6.1.4     Oscillating Pulse Method

2.6.2       Single Phase Permeability Measurements

2.6.3       NMR Permeability

2.6.4       Relative Permeability

2.6.4.1     Relative Permeability Measurements

2.6.4.1.1     Relative Permeability Measurements Using Digital Rock Physics

2.6.4.1.2     Relative Permeability Measurements Using Adsorption-Desorption Techniques

2.6.4.1.3     Relative Permeability Measurements Using Modified Purcell Method

2.6.5       NMR Capillary Pressure

2.6.6       Relative Permeability from NMR Pseudo-Capillary Pressure

2.7     Saturation

2.7.1       Techniques for calculating water saturation

2.7.2       Resistivity Logs

2.7.2.1     Clean Sand - Archie’s Model

2.7.2.2     Shaly-Sand Model

2.7.2.3     Laminated sand/shale model

2.7.2.4     Simandoux Model

2.7.2.5     Modified Simandoux Model

2.7.2.6     Poupon-Leveaux (Indonesia) Model

2.7.2.7     Waxman-Smits-Thomas and Dual-Water Models

2.7.2.8     Liu et al. Approach

2.7.3       NMR Saturation Estimation

2.8     Wettability

2.8.1       Wettability Measurement

2.8.1.1     Wettability Measurement Using NMR

2.8.1.2     Wettability Measurement Using Modified Amott-Harvey and XPS Techniques

2.9     Hydrocarbon Pore Volume and Reserve Estimation

2.9.1       Volumetric Analysis Theory

2.10        Problems

2.11        References for Additional Reading

3        Chapter Three: Petroleum Geochemistry in Organic-Rich Shale Reservoirs

3.1     Background

3.2     Evolution of Organic Matter

3.2.1       Diagenesis

3.2.2       Catagenesis

3.2.3       Metagenesis

3.3     Total Organic Carbon (TOC)

3.4     Kerogen, Bitumen and/ or Pyrobitumen

3.4.1       Classification of Kerogen

3.4.1.1     Type-I Kerogen

3.4.1.2     Type-II Kerogen

3.4.1.3     Type-III Kerogen

3.4.1.4     Type-IV Kerogen

3.5     Vitrinite Reflectance

3.6     Solid Bitumen Reflectance

3.7     Organic Porosity

3.8     Methods of Determining Source Rock Potential (TOC)

3.8.1       Direct Combustion

3.8.2       Indirect Method

3.8.3       Rock-Eval Pyrolysis Method

3.8.3.1     S1

3.8.3.2     S2

3.8.3.3     S3

3.8.3.4     S4

3.8.3.5     Tmax

3.8.3.6     TOC

3.8.3.7     Hydrogen Index

3.8.3.8     Oxygen Index

3.8.3.9     Productivity Index

3.8.3.10     High Oil Saturation Index

3.8.4       In-Situ Measurements

3.8.4.1     Schmoker Method

3.8.4.2     GR-TOC Method

3.8.4.3     Delta LogR Method

3.9     Original TOC and Hydrocarbon Yield Determinations

3.9.1       Organic Porosity from Rock-Eval Parameters

3.10        Thermal Maturity and Source Rock Assessment

3.10.1     Biological Markers (Biomarkers)

3.10.1.1     Tricyclic Terpanes (TT) (C19 – C30)

3.10.1.2     Tetracyclic Terpanes (TeT)

3.10.1.3     Hopanes and Steranes (C27+)

3.10.2     Diamondoids

3.11        Raman Spectroscopy Analysis of Thermal Maturity in Kerogen

3.11.1     Thermal Maturity Controls of Organic Matter Types in LEF Samples

3.11.2     Maturity-related Changes

3.12        DRIFTS Analysis of Kerogen Maturity

3.13        Problems

3.14        References for Additional Readings

4        Chapter 4: Application of Imaging Techniques in the Characterization of Organic-Rich Shales 

4.1     X-ray Micro Computed Tomography (X-Ray Micro-CT)

4.1.1       Operation of X-Ray Micro-CT

4.1.2       Sample Preparation

4.1.3       X-ray Micro-CT Scanning Procedure

4.1.4       Image Reconstruction

4.1.5       Application of X-ray Micro-CT on Shale Samples

4.1.6       Image Visualization and Processing

4.1.7       Estimating Porosity from CT number (CTN) of CT Images

4.1.8       Permeability Estimation from CT scanner

4.1.9       Two-phase fluid saturations

4.2     X-ray Nano-CT

4.2.1       Sample preparation for X-ray Nano-CT

4.2.2       4.2.2 In-situ Wettability and Spontaneous Imbibition at Nano-scale

X-ray Imaging Techniques, What to Expect and What can be Analyzed

4.3     Electron Microscopy

4.3.1       Scanning Electron Microscopy (SEM)

4.3.2       SEM/BSE Images of Various Ultra-Tight, Organic-Rich Formations

4.3.2.1     Depositional Kerogen (DK) versus Migrated Bitumen (MB)

4.3.3       Energy-Dispersive X-ray Spectrometry (EDS/EDX)

4.3.4       Quantitative Evaluation of Minerals by Scanning Electron Microscopy (QEMSCAN)

4.3.5       Focused Ion Beam-Scanning Electron Microscopy (FIB-SEM)

4.3.6       Three-Dimensional (3D) Rock Model

4.3.7       Pore Network Model (PNM) and Pore Size Distribution (PSD)

4.3.7.1     Tortuosity

4.3.8       Permeability Estimation

4.4     Broad Ion Beam-Scanning Electron Microscopy (BIB-SEM)

4.4.1       Sample Preparation, BIB-SEM Acquisition and Processing

4.5     Acknowledgment

4.6     Practice Questions on Micro- and Nano-CT

4.7     Practice Questions on Electron Microscopy

4.8     References

5        Chapter Five: Geomechanical Properties of Unconventional Reservoirs

5.1     Background

5.2     Basic Concepts and Definitions

5.2.1  Stress

5.2.2   Strain

5.2.3   Elastic Constants

5.2.3.1 Elastic modulus

5.2.3.2     Shear Modulus

5.2.3.3     Bulk Modulus

5.2.4       Poisson’s Ratio

5.3     Stresses and Pressure Gradients

5.3.1       Vertical Stress and Overburden Pressure

5.3.2       Effective Vertical Stress

5.3.3       Effective Horizontal Stress

5.3.4       Biot’s Poroelastic Constant

5.3.5       Horizontal Stresses and Fracturing Pressure

5.3.5.1     Maximum Horizontal Stress

5.3.5.2     Minimum Horizontal Stress

5.3.5.3     Fracture Initiation Pressure

5.3.5.4     Measuring the Fracturing Pressure

5.3.5.5     Fracture Closure Pressure

5.4     Well Logging Measurements to Determine the Elastic Parameters

5.4.1       Calculating the Dynamic Moduli

5.4.1.1     Wave Velocity Equations

5.4.1.2     Wave Travel-Time Equations

5.4.2       Correlations for Static Moduli

5.4.2.1     Static Young’s Modulus

5.4.2.2     Static Poisson’s Ratio

5.4.2.3     Static Shear Modulus and Static Bulk Modulus

5.5     Identifying the Geomechanical Sweet Spots

5.5.1       Brittleness Index

5.5.1.1     Elastic Brittleness Index

5.5.1.2     Mineral-Based Brittleness Index

5.6     General Remarks

5.7     Problems

5.8     References for Additional Readings

6        Chapter Six: Hydraulic Fracturing

6.1     Background

6.2     Fundamentals of Hydraulic Fracturing

6.2.1       Fracture Geometry

6.2.2       Fracture Conductivity

6.2.2.1     Dimensionless fracture conductivity

6.2.3       Folds of Increase

6.2.4       Multi-Stage Hydraulic Fracturing

6.2.4.1     Open-hole Completion

6.2.4.2     Plug and Perf Completion

6.2.4.3     Sliding Sleeve Completion

6.2.5       Stress Shadow

6.2.6       Zipper Fracturing

6.2.7       Fracture Hits

6.2.7.1     Frac Hit Classifications

6.2.7.2     Frac Hit Impacting Factors

6.2.7.3     Frac Hit Mitigation

6.2.8       Surface Pumps

6.2.9      Minifrac and DFIT Tests

6.2.9.1   G Function and G plot

6.2.9.2  Identifying Fracture Closure

6.2.9.3 Estimating Formation Permeability

6.2.10 Microseismic Monitoring

6.2.11 Stimulated Reservoir Volume

6.3     Fracturing Fluids

6.3.1  Purpose

6.3.2  Fracturing Fluid Types, Properties and Selection Process

6.3.2.1  Oil-Based Fracturing Fluids

6.3.2.2  Water-Based Fracturing Fluids

6.3.2.3  Multiphase-Based Fracturing Fluids

6.3.2.4   Fracturing Fluid Properties

6.3.3     Rheology of Fracturing Fluids

6.3.4     Damage of Fracturing Fluid and Fracture Cleanup

6.3.5     Fracturing Fluids Additives

6.3.5.1  Crosslinkers

6.3.5.2   pH Adjusters and Buffers

6.3.5.3   Biocides

6.3.5.4   Surfactants

6.3.5.5   Gel Stabilizers

6.3.5.6   Clay Stabilizers

6.3.5.7   Breakers

6.3.5.8   Fluid Loss Additives

6.3.5.9   Diverting Agents

6.3.5.10  Friction Reducers

6.3.5.11  Scale inhibitors

6.4     Proppant

6.4.1   Purpose

6.4.2   Proppant Characteristics and Selection Process

6.4.2.1 Proppant Grain Size

6.4.2.2 Proppant Shape

6.4.2.3 Proppant Bulk Density and Specific Gravity

6.4.2.4 Proppant Quality

6.4.2.5 Proppant Strength

6.4.3   Proppant Types

6.4.3.1 Sand Proppant

6.4.3.1.1 Ottawa Sand

6.4.3.1.2 Brady Sand

6.4.3.1.3  Fit-For-Purpose Sand

6.4.3.2 Artificial Proppant

6.4.3.2.1 Bauxite Proppant

6.4.3.2.2  Intermediate-Strength Ceramic Proppant

6.4.3.2.3  Lightweight Ceramic Proppant

6.4.3.3  Ultra-Lightweight Proppant

6.4.3.4  Resin-Coated Proppant

6.4.4  Proppant Flowback

6.4.5  Proppant Transport

6.4.6  Proppant Schedule

6.5  Modeling of Hydraulic Fractures

6.5.1 Importance of Modeling

6.5.2 Governing Processes of the Models

6.5.3 Modeling History

6.5.3.1 Early models

6.5.3.1.1  PKN Model

6.5.3.1.2  KGD Model

6.5.3.2     Advanced Models

6.5.3.2.1  Pseudo-3D Models

6.5.3.2.2  Planar 3D Models

6.5.3.2.3  Fully 3D Models

6.5.3.2.4  Unconventional Models

6.6 Problems

6.7  References for Additional Readings

7     Chapter 7 Phase Behavior of Shale Oil and Gas

7.1   Introduction

7.2   Compositional Analyses of Shale Fluids

7.2.1 Subsurface sampling

7.2.2 Surface sampling

7.3   Phase Behavior and PVT Experiments

7.3.1 Phase diagrams

7.3.2  PVT experiments and data quality check

7.4   Equation of State (EOS)

7.4.1  Cubic equation of state

7.4.2  Stability analysis

7.4.3  Confinement/pore proximity effect on phase behavior

7.4.3.1 Capillary pressure in flash calculation

7.4.3.2 Critical properties shift in EOS

7.4.3.3 Modified PR EOS

7.4.4   Phase diagrams of Bakken, Eagle Ford, and Wolfcamp fluids

7.4.5  Diffusion coefficient

7.5     EOS Regression to Experimental Data

7.6     Minimum Miscibility Pressure

7.6.1   Experimental methods

7.6.1.1 Slim tube test

7.6.1.2 Rising bubble apparatus (RBA) test

7.6.1.3 Vanishing interfacial tension technique (VIT)

7.6.1.4 Swelling/Extraction test

7.6.2    Analytical methods

7.6.3     Numerical methods

7.6.4   Correlation methods

7.7     Chapter Problem

7.7.1   Problem Statement

7.8     References

8        Fluid Flow Through Nano-sized Pores

8.1     Introduction

8.2     Pore size distribution

8.3     Adsorption

8.4     Flow Regimes

8.5     Modeling Techniques

8.5.1       Fluid transport in confined enclosures

8.5.2       Apparent permeability of shale

8.5.3       Transport in organic nanopores

8.5.4       Molecular Simulations

8.5.5       Molecular Structure of Kerogen

8.5.6       Multiscale modeling techniques

8.6     Lattice Boltzmann Model (LBM)

8.6.1       LBM Simulation

8.6.2       Implementation of LBM Simulation in Organic Nanopores

8.6.2.1     Boundary Conditions

8.6.2.2     Fluid-Fluid and Fluid-Solid Interaction Forces

8.6.2.3     Bounce-back/Specular Reflection Implementation of the Langmuir slip Model

8.6.3   Apparent Permeability

8.7     Appendix

8.8     References

9        Chapter Nine: Decline Curve and Rate Transient Analysis

9.1     Background

9.2     Purpose of Decline Curves

9.3     Decline Curve Assumptions and Limitations

9.4     Traditional Decline Curve Models

9.5     Arps’ Models

9.5.1.1     Exponential Decline Model

9.5.1.2     Determination of Exponential Decline Graphically

9.5.1.3     Harmonic Decline Model

9.5.1.4     Determination of Harmonic Decline Graphically

9.5.1.5     Hyperbolic Decline Model

9.5.1.6     Determination of Hyperbolic Decline Parameters

9.6     Modern Decline Curve Models

9.6.1       Modified Hyperbolic Model

9.6.2       Power-Law Exponential Model

9.6.3       Stretched Exponential Model

9.6.4       Logistic Growth Model

9.6.5       Duong Model

9.7     Rate Transient Analysis

9.7.1       Purpose and Features of RTA

9.7.2       RTA Concept

9.7.3       Type Curves

9.7.4       Type Curve Methods

9.7.4.1.1     Fetkovich Type Curves

9.7.4.1.2     Blasingame Type Curves

9.7.4.1.3     Agarwal-Gardner Type Curves

9.7.4.1.4     Normalized Pressure Integral (NPI) Type Curves

9.7.4.1.5     Wattenbarger Type Curves

9.7.5       Square-Root Time and Flowing Material Balance Plots

9.7.6       Flow Regimes

9.8     Problems

9.9     References

10      Chapter 10: Petroleum Economics of Unconventional Shale Reservoirs

10.1        Introduction

10.2        Effect of Shale Oil/Gas Developments on the Economics and Energy Security

10.3        Fundamentals of Petroleum Economics

10.3.1     Business Expenditures

10.3.2     Basic Cash Flow

10.3.3     Interest Rate

10.3.4     Future Value

10.3.5     Present Value

10.3.6     Net Present Value (NPV)

10.3.7     Rate of Return (ROR)

10.3.7.1     Return on Investment (ROI)

10.3.7.2     Discounted Return on Investment (DROI)

10.3.7.3     Internal Rate of Return (IRR)

10.3.8     Payout

10.4        Fiscal Regimes and Contracts

10.4.1     The Concessionary System (Royalty/Tax system)

10.4.2     The Production Sharing Contracts (PSCs)

10.4.3     Service Contracts

10.5        Decision, Uncertainty and Risk Analysis

10.6        Chapter Project

10.6.1     Project Data

10.6.2     Project Calculations

10.7   Problems

10.8   References

11      Environmental Aspects of Shale Hydrocarbon Reservoir Developments

11.1    Introduction

11.2    Water Management and Reuse

11.2.1  Basic Terminology Related to Water Management and Reuse

11.2.2     Water Cycle in Oil and Gas Production

11.2.3     Water Acquisition for Hydraulic Fracturing

11.2.4     Flowback and Produced Water Quantity and Quality

11.2.5     Flowback and Produced Water Reuse

11.3        Chemicals used in Fracturing Fluids

11.4        Potential Impacts on Drinking Water Resources

11.5        Induced Seismicity

11.6        Air Pollution

11.7        References